For the purpose of this document, and in line with the general definition of the term, “acoustic waves” are defined to include both sound and ultrasound waves. Similarly, “acoustic noise” includes both sound and ultrasound noise.
In the well, the acoustic waves originating from a leakage and the acoustic waves originating from other sources are both termed acoustic noise, although within the technical discipline of leakage detection, the noise from the leakage can be seen as the desired signal to be detected, and the noise from other sources can be seen as the background noise. The difference between the desired signal and the background noise is defined as the signal to noise ratio. In this document the acoustic waves originating from a leakage are termed “noise signal”, while the acoustic waves originating from other sources are termed “background noise”.
Leakages through wellbore tubular walls, such as tubing or casing or other wellbore barriers, such as formation leaks, can reduce a well's performance throughout its life and cause serious health, safety and environmental issues. With conventional leak-detection methods reliability of diagnosis varies, as results can be affected by both leak-rate, leak size and location.
The term Leakage is used in this document to describe any cause of unwanted flow from one location in the well to another, typically across breached well barriers. Such leakages threaten well integrity. Fluid flow is driven across a breached barrier by differential pressure, with fluid running from a higher to a lower pressure side. Flow through a well-localized leakage point, e.g. through a hole opening in tubing or past threads in a piping joint, is typically termed a leak, while leakages along distributed channels are termed flow paths.
Leakage rate describes the fluid volume flow as a function of time, and for a given leak size, a larger leakage rate will induce more acoustic noise and thus be easier to detect than a lower leakage rate.
On the other hand, the degree of noise-inducing fluid turbulence is more closely related to fluid velocity than fluid rate, and a small rate leakage through a small size flow restriction may thus be easier to detect than a larger rate leakage through a larger opening. A large leak can be challenging to detect acoustically if the velocity is low.
In addition, multiple leaks and leaks beyond the primary tubular are generally more challenging to detect and locate efficiently.
Further, barrier failures can occur due to mechanical failures or weakness, or changes in the wellbore pressure. This leads to an unwanted flow that can have a variety of outcomes, including poor well performance, ground water or reservoir contamination and/or more catastrophic, uncontrolled fluid escape at surface.
The unwanted flow, often seen as turbulent liquid or gas flowing through small restrictions in the annuli, generates acoustic waves that can be detected by sensor devices and systems adapted for this purpose. It is important not only to detect that a leak has occurred, but also be able to specify the location of the origin of the flow. This usually involves a combination of downhole acoustic sensors and equipment for processing the data.
The processed data can typically represent a noise profile over the length of the wellbore. Areas with excessive noise could indicate a leak or a flow.
High reliability of the results obtained is important, since the next action to be taken depends on the reliability of the result. Confidence in the data enables faster, more effective remediation decisions and potentially, can save wells from premature re-completion or abandonment.
It should be noted initially that although both flow detection and acoustic logging often use results of acoustic measurements to obtain the desired set of data, there is an important difference when it comes to the signals actually detected. For acoustic logging purposes the logging tool often comprises both transmitters and receivers, or in some cases, only receivers if the transmitters are placed in a different location. However, in both cases, the transmitters and receivers are part of the system, and the location of the transmitters and receivers are known. This could mean signal encoding and decoding, predetermined frequency hopping etc. to allow background noise to be cancelled out.
This is not the case for a noise detection system, where there is no known transmitter. The characteristics and location of the noise signal will differ from one leak to the other and the receiver or sensor will have to rely on a signal that is in principle totally unknown. Thus, signal/noise improvement techniques such as mentioned used for traditional wellbore logging systems cannot be used for a noise detection system.
It is common in the field to perform stationary logging in the wellbore for the purpose of detecting leaks and flows. The logging tool is then positioned at a specific location while the measurement, by e.g. acoustic sensors is performed. For deep wellbores such stationary measurements take long time, since a large number of stations is required to obtain the necessary data for further processing to locate the potential leak.
It is possible to use dynamic logging, i.e. continuous scanning, or combinations of dynamic and stationary logging to determine locations of unwanted leaks and flows faster. Stationary logging is then used in regions of the wellbore of specific interest, e.g. as a result of indications obtained during dynamic logging.
International patent publication WO2011091505 (A1) discloses how signals from a number of acoustic sensing means, adapted to sense individual acoustic signals from a plurality of corresponding locations along said wellbore, are analysed to determine if there exists a common acoustic component in acoustic signals generated from proximate locations in said wellbore.
For acoustic well tools, it is well known that the accuracy can be improved by keeping the tool centred in the tubular. Typically, centralizers with spring-loaded arms are integrated in the tool string to keep the tool centred, with rollers or similar making contact with the inner walls of the surrounding tubular.
One drawback with the use of centralizers in such applications is that the centralizers contribute to generate so called “road noise” when the tool is travelling up and down the well due to the mechanical contact between the centralizer and the tubular. Road noise may significantly reduce the signal to noise ratio with dynamic logging.
Stationary measurements can be used to avoid such background noise problems, but this requires much more time than dynamic logging. One way to overcome this problem is to combine scanning with stationary measurements to obtain a better signal/noise ratio of areas of specific interest. However, this takes more time and is more complex than dynamic logging.
Road noise propagates through the fluid of the wellbore and through the body of the tool. Some road noise is related to the continuous scratching or rolling of the centralizers along the inner wall of the tubular, while a different type of background noise occurs when the centralizers passes joints, step change in inner diameter, or other construction details. This latter background noise has the character of a mechanical impact noise.
Typically, road noise is low frequent and some of the noise can be filtered out by a high pass filter directly. However, this could reduce the reliability of the data, since important low frequency noise profiles can be lost.
U.S. Pat. No. 3,991,850 (A) discloses a system for reducing acoustic background noise, or road-noise inherently generated by the rubbing of the outward faces of the spring members of the centralizers along the well bore walls by covering a portion of the inward faces of the spring members with a composite material including an elastomer containing a substantial number of small embedded particles or interspersed balls of a sound absorbing material such as lead.
The wellbore pressure can be in the order of 1000 bars or 109 Pa. Thus, the tool and all the components have to withstand high pressure.
In prior art it is well known to use hydrophones for leak detection. Hydrophones have a good sensitivity for lower frequencies, and the response is relatively flat over its bandwidth. However, one problem related to hydrophones is that the road noise described above is most prominent in the audible range—which typically coincides with dominant bandwidth for hydrophone-based downhole tools. Another drawback with hydrophones, is that tool-integration is generally complex mechanically. Typically, hydrophone integration in a downhole tool may involve protected mounting within an internal oil filled chamber, with a piston or membrane arrangement used to equalize pressure with the surrounding well fluid. Pressure equalization allows for using a thinner tool housing locally in order to reduce losses, but having a metal barrier to an internal oil chamber remains non-optimal for acoustic signal transfer. As will be understood, such hydrophone arrangements also require relatively frequent maintenance.
US patent application publication US20100268489 discloses a method of quantifying, detecting and localizing one or more leaks or a flow of liquid, gasses, or particles, in an oil or gas producing well, wherein said method employs at least one acoustic transducer deployed in operation in the well, characterized by that said method comprises steps of:    (a) detecting one or more signals using the at least one acoustic transducer, wherein said one or more signals are generated by acoustic noise from one or more leaks or flow of liquid, gasses, or particles in a region surrounding said at least one transducer;    (b) amplifying said one or more signals to generate one or more corresponding amplified signals for inputting into a processing unit local to the at least one transducer;    (c) filtering said one or more amplified signals over several frequency ranges by utilizing dynamic filtering for improving signal-to-noise ratio by filtering away background noise in said one or more amplified signals, thereby generating corresponding filtered data; and    (d) processing said filtered data in said processing unit for transmitting said filtered data to a unit including a computer in a surface region remote from the at least one acoustic transducer for storage and/or viewing of said filtered data, said computer being adapted to perform simultaneous resolution of said filtered data to identify occurrence of said one or more leaks or a flow of liquid, gasses, or particles, in an oil or gas producing well.
U.S. Pat. No. 5,354,956 depicts an ultra-sonic sensor assembly for a downhole tool comprising a sensor stack having an inner sound absorbing backing element and a piezoelectric ceramic disk stacked outwardly adjacent said backing element, an impedance matching layer disposed outwardly adjacent said ceramic disk, a rubber jacket having sides which are disposed outwardly around said backing element, said ceramic disk and said matching layer, and an end disposed adjacent said impedance matching layer, a delay-line of rigid material disposed outwardly of said ceramic disk, said delay-line having inner and outer ends, said inner end facing said end of said rubber jacket, and first and second electrical connectors, and inner and outer electrode means for connecting inner and outer sides of said disk to said first and second electrical connectors.